The current invention is directed to a method and apparatus for transmitting information from a down hole location in a well to the surface, such as that used in a mud pulse telemetry system employed in a drill string for drilling an oil well.
In underground drilling, such as gas, oil or geothermal drilling, a bore is drilled through a formation deep in the earth. Such bores are formed by connecting a drill bit to sections of long pipe, referred to as a xe2x80x9cdrill pipe,xe2x80x9d so as to form an assembly commonly referred to as a xe2x80x9cdrill stringxe2x80x9d that extends from the surface to the bottom of the bore. The drill bit is rotated so that it advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In directional drilling, the drill bit is rotated by a down hole mud motor coupled to the drill bit; the remainder of the drill string is not rotated during drilling. In a steerable drill string, the mud motor is bent at a slight angle to the centerline of the drill bit so as to create a side force that directs the path of the drill bit away from a straight line. In any event, in order to lubricate the drill bit and flush cuttings from its path, piston operated pumps on the surface pump a high pressure fluid, referred to as xe2x80x9cdrilling mud,xe2x80x9d through an internal passage in the drill string and out through the drill bit. The drilling mud then flows to the surface through the annular passage formed between the drill string and the surface of the bore.
Depending on the drilling operation, the pressure of the drilling mud flowing through the drill string will typically be between 1,000 and 25,000 psi. In addition, there is a large pressure drop at the drill bit so that the pressure of the drilling mud flowing outside the drill string is considerably less than that flowing inside the drill string. Thus, the components within the drill string are subject to large pressure forces. In addition, the components of the drill string are also subjected to wear and abrasion from drilling mud, as well as the vibration of the drill string.
The distal end of a drill string, which includes the drill bit, is referred to as the xe2x80x9cbottom hole assembly.xe2x80x9d In xe2x80x9cmeasurement while drillingxe2x80x9d (MWD) applications, sensing modules in the bottom hole assembly provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a steerable drill string. Such sensors may include a magnetometer to sense azimuth and accelerometers to sense inclination and tool face.
Historically, information concerning the conditions in the well, such as information about the formation being drill through, was obtained by stopping drilling, removing the drill string, and lowering sensors into the bore using a wire line cable, which were then retrieved after the measurements had been taken. This approach was known as wire line logging. More recently, sensing modules have been incorporated into the bottom hole assembly to provide the drill operator with essentially real time information concerning one or more aspects of the drilling operation as the drilling progresses. In xe2x80x9clogging while drillingxe2x80x9d (LWD) applications, the drilling aspects about which information is supplied comprise characteristics of the formation being drilled through. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation.
In traditional LWD and MWD systems, electrical power was supplied by a turbine driven by the mud flow. More recently, battery modules have been developed that are incorporated into the bottom hole assembly to provide electrical power.
In both LWD and MWD systems, the information collected by the sensors must be transmitted to the surface, where it can be analyzed. Such data transmission is typically accomplished using a technique referred to as xe2x80x9cmud pulse telemetry.xe2x80x9d In a mud pulse telemetry system, signals from the sensor modules are typically received and processed in a microprocessor-based data encoder of the bottom hole assembly, which digitally encodes the sensor data. A controller in the control module then actuates a pulser, also incorporated into the bottom hole assembly, that generates pressure pulses within the flow of drilling mud that contain the encoded information. The pressure pulses are defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time). Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data (i.e., bit 1 or 0)xe2x80x94for example, a pressure pulse of 0.5 second duration represents binary 1, while a pressure pulse of 1.0 second duration represents binary 0. The pressure pulses travel up the column of drilling mud flowing down to the drill bit, where they are sensed by a strain gage based pressure transducer. The data from the pressure transducers are then decoded and analyzed by the drill rig operating personnel.
Various techniques have been attempted for generating the pressure pulses in the drilling mud. One technique involves the use of axially reciprocating valves, such as that disclosed in U.S. Pat. Nos. 3,958,217 (Spinnler); 3,713,089 (Clacomb); and 3,737,843 (Le Peuvedic et al.), each of which is hereby incorporated by reference in its entirety. Another technique involves the use of rotary pursers. Typically, rotary pulsers utilizes a rotor in conjunction with a stator. The stator has vanes that form passages through which the drilling mud flows. The rotor has blades that, when aligned with stator passages, restrict the flow of drilling mud, thereby resulting in an increase in drilling mud pressure, and, when not so aligned, eliminate the restriction. Rotation of the rotor is driven by the flow of drilling mud or an electric motor powered by a battery. Typically, the motor is a brushless DC motor mounted in an oil-filled chamber pressurized to a pressure close to that of the drilling mud to minimize the pressure gradient acting on the housing enclosing the motor.
In one type of rotary pulser, sometimes referred to as a xe2x80x9cturbinexe2x80x9d or xe2x80x9csiren,xe2x80x9d the rotor rotates more or less continuously so as to create an acoustic carrier signal within the drilling mud. A siren type rotary pulser is disclosed in U.S. Pat. Nos. 3,770,006 (Sexton et al.) and 4,785,300 (Chin et al.), each of which is hereby incorporated by reference in their entirety. Encoding can be accomplished based on shifting the phase of the acoustic signal relative to a reference signalxe2x80x94for example, a shift in phase may represent one binary bit (e.g., 1), while the absence of a phase shift may indicate another bit (e.g., 0).
In another type of rotary pulser, in which the rotor is typically driven by the mud flow, the rotor increments in discrete intervals. Operation of a latching or escapement mechanism, for example by means of an electrically operated solenoid, may be used to actuate the incremental rotation of the rotor into an orientation in which its blades block the stator passages, thereby resulting in an increase in drilling mud pressure that may be sensed at the surface. The next incremental rotation unblocks the stator passages, thereby resulting in a reduction in drilling mud pressure that may likewise be sensed at the surface. Thus, the incremental rotation of the rotor creates pressure pulses that are transmitted to the surface detector. A rotary pulser of this type is disclosed in U.S. Pat. No. 4,914,637 (Goodsman), incorporated by reference herein in its entirety.
Unfortunately, conventional rotary pulsers suffer from disadvantages that result from the fact that the characteristics of the pressure pulses cannot be adequately controlled in situ to optimize the transmission of information. For example, under any given mud flow situation, each increment of the rotor of an incremental type rotary pulser will result in a constant amplitude pressure pulses being generated at the pulser. As the drilling progresses, the distance between the pulser and the surface detector increases, thereby resulting in increased attenuation of the pressure pulses by the time they reach the surface. This can make it more difficult for the pressure pulses to be detected at the surface. Moreover, from time to time, extraneous pressure pulses from other sources, such as mud pumps, may become more pronounced or may occur at a frequency closer to that of the pressure pulses containing the data to be transmitted, making data acquisition by the surface detection system more difficult. In such situations, data transmission could be improved by increasing the amplitude or varying the frequency or even the shape of the pressure pulses generated by the pulser.
In prior art systems, such situations can only be remedied by removing the pulser, which requires cessation of drilling and withdrawal of the drill string from the well so that physical adjustments can be made to the pulser, for example, mechanically increasing the size of the rotor increment so as to increase the amplitude and duration of the pulses, or adjusting the motor control to alter the pulser speed.
Note that although increasing the magnitude of the rotor increment will increase the duration, and often the amplitude, of the pressure pulses, it will also increase the time necessary to create the pulse, thereby reducing the data transmission rate. Thus, optimal performance will not be obtained by generating pressure pulses of greater than necessary duration or amplitude, and there are some situations in which it may be desirable to decrease the amplitude of the pressure pulses as the drilling progresses. Current systems, however, do not permit such optimization of the data transmission rate.
Conventional pulsers suffer from other disadvantages as well. For example, due to the high pressure of the drilling mud, rotary seals between the rotor shaft and the stationary components are subject to leakage. Moreover, the brushless DC motors used to drive the rotor consume relatively large amounts of power, limiting battery life. While brushed DC motors consume less power, they cannot be used in an oil-filled pulser housing of the type typically used in an MWD/LWD system.
Consequently, it would be desirable to provide a method and apparatus for generating pressure pulses in a mud pulse telemetry system in which one or more characteristics of the pressure pulses generated at the pulser could be adjusted in situ at the down hole locationxe2x80x94that is, without withdrawing the drill sting from the well. It would also be desirable to provide a pulser having a durable seal that was resistant to leakage and powered by a low power consuming brushed DC motor.
It is an object of the current invention to provide an improved method of transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth. This and other objects are achieved in a method of transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth comprising the steps of (i) generating pressure pulses in the drilling fluid flowing through the drill string that are encoded to contain the information to be transmitted, and (ii) controlling a characteristic of the pressure pulses, such as amplitude, duration, frequency, or phase, in situ at the down hole location.
In one embodiment, the method comprises the steps of (i) directing drilling fluid along a flow path extending through the down hole portion of the drill string, (ii) directing the drilling fluid over a rotor disposed in the down hole portion of the drill string, the rotor capable of at least partially obstructing the flow of fluid through the flow path by rotating in a first direction and of thereafter reducing the obstruction of the flow path by rotating in an opposite direction, (iii) creating pressure pulses encoded to contain the information in the drilling fluid that propagate toward the surface location, each of the pressure pulses created by oscillating the rotor by rotating the rotor in the first direction through an angle of rotation so as to obstruct the flow path and then reversing the direction of rotation and rotating the rotor in the opposite direction so as to reduce the obstruction of the flow path, and (iv) making an adjustment to at least one characteristic of the pressure pulses by adjusting the oscillation of the rotor, the adjustment of the oscillation of the rotor performed in situ at the down hole location.
In a preferred embodiment, the method includes the step of transmitting instructional information from the surface to the down hole location for controlling the pressure pulse characteristic. In one embodiment, the instructional information is transmitted by generating pressure pulses at the surface and transmitting them to the down hole location where they are sensed by a pressure sensor and deciphered.
The invention also encompasses an apparatus for transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth, the drill string having a passage through which a drilling fluid flows, comprising (i) a housing for mounting in the drill string passage, first and second chambers formed in the housing, the first and second chambers being separated from each other, the first chamber filled with a gas, the second chamber filled with a liquid, (ii) a rotor capable of at least partially obstructing the flow of the drilling fluid through the passage when rotated into a first angular orientation and of reducing the obstruction when rotated into a second angular orientation, whereby rotation of the rotor creates pressure pulses in the drilling fluid, (iii) a drive train for rotating the rotor, at least a first portion of the drive train located in the liquid filled second chamber, (iv) an electric motor for driving rotation of the drive train, the electric motor located in the gas-filled first chamber.
In a preferred embodiment, the apparatus also includes a stator in which the passage is formed. A seal is fixedly attached at one end to the rotor and at the other end to the stator, so that the seal undergoes torsional deflection as the rotor oscillates. The clearance between the rotor and stator is tapered so as to prevent jamming by debris in the drilling fluid.